1. Field of the Invention
The present invention relates to methods and apparatus for characterizing petroleum fluid extracted from a hydrocarbon bearing geological formation.
2. Description of Related Art
Petroleum consists of a complex mixture of hydrocarbons of various molecular weights, plus other organic compounds. The exact molecular composition of petroleum varies widely from formation to formation. The proportion of hydrocarbons in the mixture is highly variable and ranges from as much as 97 percent by weight in the lighter oils to as little as 50 percent in the heavier oils and bitumens. The hydrocarbons in petroleum are mostly alkanes (linear or branched), cycloalkanes, aromatic hydrocarbons, or more complicated chemicals like asphaltenes. The other organic compounds in petroleum typically contain carbon dioxide (CO2), nitrogen, oxygen, and sulfur, and trace amounts of metals such as iron, nickel, copper, and vanadium.
The alkanes, also known as paraffins, are saturated hydrocarbons with straight or branched chains which contain only carbon and hydrogen and have the general formula CnH2n+2. They generally have from 5 to 40 carbon atoms per molecule, although trace amounts of shorter or longer molecules may be present in the mixture. The alkanes include methane (CH4), ethane (C2H6), propane (C3H8), i-butane (iC4H10), n-butane (nC4H10), i-pentane (iC5H12), n-pentane (nC5H12), hexane (C6H14), heptane (C7H16), octane (C8H18), nonane (C9H20), decane (C10H22), hendecane (C11H24)— also referred to as endecane or undecane, dodecane (C12H26), tridecane (C13H28), tetradecane (C14H30), pentadecane (C15H32), and hexadecane (C16H34).
The cycloalkanes, also known as napthenes, are saturated hydrocarbons which have one or more carbon rings to which hydrogen atoms are attached according to the formula CnH2n. Cycloalkanes have similar properties to alkanes but have higher boiling points. The cycloalkanes include cyclopropane (C3H6), cyclobutane (C4H8), cyclopentane (C5H10), cyclohexane (C6H12), cycloheptane (C7H14), etc.
The aromatic hydrocarbons are unsaturated hydrocarbons which have one or more planar six-carbon rings called benzene rings, to which hydrogen atoms are attached with the formula CnHn. They tend to burn with a sooty flame, and many have a sweet aroma. Some are carcinogenic. The aromatic hydrocarbons include benzene (C6H6) and derivatives of benzene, as well as polyaromatic hydrocarbons.
Computer-based modeling and simulation techniques have been developed for estimating the properties and/or phase behavior of petroleum fluid in a reservoir of interest. Typically, such techniques employ a borehole sampling and analysis tool that samples petroleum fluid and analyzes the petroleum fluid at downhole conditions to derive properties of the sampled petroleum fluid at such downhole conditions. Examples of such borehole sampling and analysis tools include the Modular Formation Dynamics Tester (MDT) tool with downhole fluid analysis (DFA) module available from Schlumberger Technology Corporation of Sugar Land, Tex., USA, the SampleView Reservoir Characterization Instrument available from Baker Hughes, Inc. of Houston, Tex., USA, and the Reservoir Description Tool available from Halliburton Company of Houston, Tex., USA. As an example, the fluid properties measured by the MDT tool include weight fractions of the hydrocarbon components of the fluid, live fluid density, live fluid viscosity, gas-oil ratio (GOR), volumetric factors, flowline temperature and pressure, and formation temperature and pressure. Such fluid properties are typically used in conjunction with an equation of state (EOS) model that represents the phase behavior of the petroleum fluid in the reservoir to characterize a wide array of properties of the petroleum fluid of the reservoir. The EOS model and calculations based thereon can be extended to characterize the reservoir properties over time during planned production in order to simulate and analyze production scenarios for reservoir planning and optimization. A detailed description of reservoir fluid properties is desirable for an accurate modeling of the fluids in the reservoir. Indeed, decisions such as the type of well completion, production procedures, and the design of the surface handling and processing facilities are affected by the characteristics of the produced fluids.
Difficulties in accurately estimating the properties of petroleum fluid arise from the fact that the petroleum fluid samples captured by the borehole sampling and analysis tool are likely contaminated with drilling mud. More particularly, a borehole is drilled into the formation in order to provide access for the borehole sampling and analysis tool. During such drilling, mud is pumped into the borehole. The mud serves several purposes. It acts as a buoyant medium, cuttings transporter, lubricant, and coolant, as well as a medium through which downhole telemetry may be achieved. The mud is usually kept overbalanced, i.e. at a higher pressure than the pressure of the formation fluids. This leads to “invasion” of mud filtrate into the formation fluids and the buildup of mudcake on the borehole wall. There are three different mud types: water-based mud (WBM), oil-based mud (OBM), and synthetic-based mud (SBM). Water-based mud can be realized by, but are not limited to, freshwater, seawater, saltwater (brine) and others, or a combination of any of these fluids. Oil-based mud is an oil product, such as diesel or mineral oil. Synthetic-based mud can be realized, without limitation, by olefinic-, naphthenic-, and paraffinic-based compounds.
Water-based mud and aquifer water may form emulsions with formation petroleum fluids as a result of high speed drilling operations. When samples are taken, the samples are contaminated with the emulsified mud filtrate and even a small quantity of such mud filtrate in a sample can alter the properties of the fluid sample as measured by the tool.
For oil-based mud and synthetic-based mud, the mud filtrate may miscibly mix with the formation petroleum fluid. When samples are taken, the samples are contaminated with the mud filtrate and even a small quantity of such mud filtrate in a sample can alter the properties of the fluid sample as measured by the tool.
There are prior art techniques for estimating such mud filtrate based on the optical properties of the fluids flowing through a tool. More particularly, a fluid analysis module can measure the absorption spectrum of the formation fluid and use physical and empirical models in conjunction with the measured absorption spectrum to estimate the mud filtrate fraction, control sampling based thereon, and determine GOR of the formation fluid corrected for mud filtrate contamination. See, e.g., U.S. Pat. Nos. 6,178,815; 6,274,865; 6,343,507 and 6,350,986. Such techniques have several limitations, including the generation of a limited data set (e.g., mud filtrate fraction, GOR) that characterizes properties of the formation fluid in a real-time manner. Instead, other fluid properties of interest can be derived with significant delay, which typically results from a time period required to allow non-contaminated petroleum fluid to be sampled and analyzed by the tool.
In another example, U.S. Pat. No. 7,134,500 discloses a method for characterizing formation fluid using flowline viscosity and density data in an oil-based mud environment. However, this method has several limitations. First, it requires computational analysis of a one-dimensional column of measurements of density, viscosity, volume fraction of water, and volume fraction of mud filtrate over a number of samples that cannot be applied in real-time. Second, the method employs mixing rules that ignore excess volume created during mixing processes and cannot generate accurate fluid properties for high GOR systems, especially gas condensate. Third, the method usually calculates much higher density of oil-based mud than the actual experimental value.